U.S. patent application number 15/621574 was filed with the patent office on 2018-12-13 for profile measurement for underground hydrocarbon storage caverns.
The applicant listed for this patent is James N. McCoy, Orvel L. Rowlan. Invention is credited to James N. McCoy, Orvel L. Rowlan.
Application Number | 20180355713 15/621574 |
Document ID | / |
Family ID | 64563297 |
Filed Date | 2018-12-13 |
United States Patent
Application |
20180355713 |
Kind Code |
A1 |
McCoy; James N. ; et
al. |
December 13, 2018 |
PROFILE MEASUREMENT FOR UNDERGROUND HYDROCARBON STORAGE CAVERNS
Abstract
Underground storage caverns are widely used for the bulk storage
of petroleum products, in particular, crude oil. These caverns can
store millions of barrels of hydrocarbon liquid safely for long
periods of time at low cost. The caverns are accessed through a
casing in a borehole down to the cavern. The lower end of the
casing opens into an upper region of the cavern termed the chimney.
The chimney provides a transition from the casing into the cavern
body. The lower end of the casing has a structure termed a casing
shoe which seals the earth formation around the casing from the
interior of the chimney. The chimney region needs to be
periodically inspected to determine if it is stable. The salt
structure of the cavern is subject to erosion and collapse of
sections of the wall. Deterioration of the physical structure of
the chimney can also lead to the opening of cracks which may allow
the stored liquid to leak into the formations around the casing and
the chimney. The invention presents a process of injecting a gas
into the well while measuring the gas pressure and optionally
measuring the volume of injected gas. The gas drives down an
interface between the gas and hydrocarbon liquid. By monitoring the
rate of change of the gas pressure, and detecting a sudden decrease
in the rate of change, it can be determined when the interface has
been driven down to the region immediately below the bottom of the
casing at the upper end of the chimney. This determines a critical
location for the interface. Further steps of injecting gas and
measuring gas pressure are used to determine the profile of the
chimney.
Inventors: |
McCoy; James N.; (Wichita
Falls, TX) ; Rowlan; Orvel L.; (Wichita Falls,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
McCoy; James N.
Rowlan; Orvel L. |
Wichita Falls
Wichita Falls |
TX
TX |
US
US |
|
|
Family ID: |
64563297 |
Appl. No.: |
15/621574 |
Filed: |
June 13, 2017 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 47/117 20200501;
E21B 47/06 20130101 |
International
Class: |
E21B 47/10 20060101
E21B047/10; E21B 47/06 20060101 E21B047/06 |
Claims
1. A method for use in a cavern storage well which has a casing
that extends from the earth surface down to a chimney region that
extends downward and opens into a cavern body wherein hydrocarbon
liquid is stored in the cavern body above a liquid more dense than
the hydrocarbon liquid, the method indicating when an interface
between a gas and the hydrocarbon liquid is located at the top of
said chimney a short distance below the lower end of said casing,
comprising the steps of: injecting the gas into said casing at the
earth surface at a constant rate of flow to drive the interface
downward, measuring the pressure of said gas in said casing at the
earth surface to produce a series of gas pressure measurements (P1,
P2, P3 . . . ) at a sequence of respective times (T1, T2, T3 . . .
), producing a series of gas pressure rate of change values
(.DELTA.P1, .DELTA.P2, . . . ) based on said gas pressure
measurements and time intervals between said times for adjacent
pairs of said gas pressure measurements (.DELTA.P1=[P2-P1]/[T2-T1],
.DELTA.P2=[P3-P2]/[T3-T2] . . . ), and comparing each of a group of
said gas pressure rate of change values (.DELTA.P1, .DELTA.P2, . .
. ) to a preceding one of said gas pressure rate of change values
to detect when a gas pressure rate of change value is initially
less than a predetermined percentage of said preceding one of said
gas pressure rate of change values, thereby indicating that said
interface is located within the top region of said chimney below
the lower end of said casing between the times when said less than
a predetermined percentage gas pressure rate of change value gas
pressure measurements were made.
2. The method recited in claim 1 wherein said preceding one of said
gas pressure rate of change value is the immediately preceding gas
pressure rate of change value before said gas pressure rate of
change value which was detected to have a value that is initially
less than a predetermined percentage of a preceding gas pressure
rate of change value.
3. The method recited in claim 1 wherein said preceding one of said
gas pressure rate of change value is one of the preceding gas
pressure rate of change values other than the immediately preceding
gas pressure rate of change value before said pressure rate of
change value which was detected to have a value that is initially
less than a predetermined percentage of a preceding gas pressure
rate of change value.
4. The method recited in claim 1 including the following steps for
producing a profile of said chimney: after said interface has been
located at the top region of said chimney below the lower end of
said casing, further injecting said gas into said casing at said
earth surface and measuring said gas pressure at the earth surface
to produce a series of depth gas pressure measurements (Pd1, Pd2,
Pd3, . . . ), measuring the mass of said gas injected into said
casing between each pair of depth gas pressure measurements,
determining a series of change in depth values (.DELTA.d1,
.DELTA.d2, .DELTA.d3 . . . ), each depth value based on a gas
pressure change value (.DELTA.Pd1, .DELTA.Pd2, . . . ) between two
adjacent depth gas pressure measurements (.DELTA.Pd1=Pd2-Pd1,
.DELTA.Pd2=Pd3-Pd2, . . . ) and a gradient (G pressure/distance)
value of said hydrocarbon liquid, wherein the change in depth
values are (.DELTA.d1=.DELTA.Pd1/G, .DELTA.d2=.DELTA.Pd2/G, . . .
), and wherein a series of profile measurements of said chimney are
produced, each said profile measurement defined by (1) a change in
depth value and (2) a volume of gas caused by said mass of said gas
injected into said casing between each pair of corresponding depth
gas pressure measurements which define the change in depth value
(1).
5. The method recited in claim 1 wherein said predetermined
percentage is 50%.
6. A method for use in a cavern storage well which has a casing
that extends from the earth surface down to a chimney region that
extends downward and opens into a cavern body wherein hydrocarbon
liquid is stored in the cavern body above a liquid more dense than
the hydrocarbon liquid, the method indicating when an interface of
a gas with the hydrocarbon liquid is located at the top of said
chimney a short distance below the lower end of said casing,
comprising the steps of: injecting the gas into said casing at the
earth surface at a constant rate of flow to drive said interface
downward, measuring the pressure of said gas in said casing at the
earth surface to produce a series of gas pressure measurements (P1,
P2, P3 . . . ) at a sequence of corresponding times (T1, T2, T3 . .
. ), producing a series of gas pressure rate of change values
(.DELTA.P1, .DELTA.P2, . . . ) based on said gas pressure
measurements and time intervals between said times for adjacent
pairs of said gas pressure measurements (.DELTA.P1=[P2-P1]/[T2-T1],
.DELTA.P2=[P3-P2]/[T3-T2] . . . ), and comparing each of said gas
pressure rate of change values (.DELTA.P1, .DELTA.P2, . . . ) to a
running average value of a plurality of preceding ones of said gas
pressure rate of change values to detect when a gas pressure rate
of change value is initially less than a predetermined percentage
of the running average value, thereby indicating that said
interface is located within the top region of said chimney below
the lower end of said casing between the times when said gas
pressure measurements were made for the less than predetermined
percentage gas pressure rate of change value.
7. The method recited in claim 6 including the following steps for
producing a profile of said chimney: after said interface has been
located at the top region of said chimney below the lower end of
said casing, further injecting said gas into said casing at said
earth surface and measuring said gas pressure at the earth surface
to produce a series of depth gas pressure measurements (Pd1, Pd2,
Pd3, . . . ), measuring the mass of said gas injected into said
casing between each pair of depth gas pressure measurements,
determining a series of change in depth values (.DELTA.d1,
.DELTA.d2, .DELTA.d3 . . . ), each depth value based on a gas
pressure change value (.DELTA.Pd1, .DELTA.Pd2, . . . ) between two
adjacent depth gas pressure measurements (.DELTA.Pd1=Pd2-Pd1,
.DELTA.Pd2=Pd3-Pd2, . . . ) and a gradient (G pressure/distance)
value of said hydrocarbon liquid, wherein the change in depth
values are (.DELTA.d1=.DELTA.Pd1/G, .DELTA.d2=.DELTA.Pd2/G, . . .
), and wherein a series of profile measurements of said chimney are
produced, each said profile measurement defined by (1) a change in
depth value and (2) said mass of said gas injected into said casing
between each pair of corresponding depth gas pressure measurements
which define the change in depth value (1).
8. The method recited in claim 6 wherein said running average
comprises seven of said gas pressure rate of change values.
9. A method for use in a cavern storage well which has a casing
that extends from the earth surface down to a chimney region that
extends downward and opens into a cavern body wherein hydrocarbon
liquid is stored in the cavern body above a liquid more dense than
the hydrocarbon liquid, the method indicating when an interface of
gas with the hydrocarbon liquid is located at the top of said
chimney a short distance below the lower end of said casing,
comprising the steps of: injecting a gas into said casing at the
earth surface to drive said interface downward, measuring the
volume of said gas injected into said casing to produce a series of
gas volume measurements (V1, V2, V3 . . . ) at respective times T1,
T2, T3 . . . measuring the pressure of said gas in said casing at
the earth surface to produce a series of gas pressure measurements
(P1, P2, P3 . . . ) at times (T1, T2, T3, . . . ) with said gas
volume measurements, producing a series of gas pressure rate of
change values (.DELTA.P1, .DELTA.P2, . . . ) based on said gas
pressure measurements and said gas volume measurements wherein
(.DELTA.P1=[P2-P1]/[V2-V1], .DELTA.P2=[P3-P2]/[V3-V2] . . . ), and
comparing each of said gas pressure rate of change values
(.DELTA.P1, .DELTA.P2, . . . ) to a preceding one of said pressure
rate of change values to detect when a gas pressure rate of change
value is initially less than a predetermined percentage of a
preceding gas pressure rate of change value, thereby indicating
that said interface is located within the top region of said
chimney below the lower end of said casing between the times when
the gas pressure measurements were made for said gas pressure rate
of change value that is initially less than a predetermined
percentage of a preceding gas pressure rate of change value.
10. The method recited in claim 9 wherein said gas volume
measurements are based on measuring the mass of said gas injected
into said casing.
11. The method recited in claim 9 including the following steps for
producing a profile of said chimney: after said interface has been
located at the top of region said chimney below the lower end of
said casing, further injecting said gas into said casing at said
earth surface and measuring said gas pressure at the earth surface
to produce a series of depth gas pressure measurements (Pd1, Pd2,
Pd3, . . . ), measuring the mass of said gas injected into said
casing between each pair of depth gas pressure measurements,
determining a series of change in depth values (.DELTA.d1,
.DELTA.d2, .DELTA.d3 . . . ), each depth value based on a gas
pressure change value (.DELTA.Pd1, .DELTA.Pd2, . . . ) between two
adjacent depth gas pressure measurements (.DELTA.Pd1=Pd2-Pd1,
.DELTA.Pd2=Pd3-Pd2, . . . ) and a gradient (G pressure/distance)
value of said hydrocarbon liquid, wherein the change in depth
values are (.DELTA.d1=.DELTA.Pd1/G, .DELTA.d2=.DELTA.Pd2/G, . . .
), and wherein a series of profile measurements of said chimney are
produced, each said profile measurement defined by (1) a change in
depth value and (2) a volume of gas caused by said mass of said gas
injected into said casing between each pair of corresponding depth
gas pressure measurements which define the change in depth value
(1).
12. The method recited in claim 9 wherein said predetermined
percentage is 50%.
13. A method for use in a cavern storage well which has a casing
that extends from the earth surface down to a chimney region that
extends downward and opens into a cavern body wherein hydrocarbon
liquid is stored in the cavern body above a liquid more dense than
the hydrocarbon liquid, the method indicating when an interface of
a gas with the hydrocarbon liquid is located at the top of said
chimney a short distance below the lower end of said casing,
comprising the steps of: injecting the gas into said casing at the
earth surface to drive said interface downward, measuring the
volume of said gas injected into said casing to produce a series of
gas volume measurements (V1, V2, V3 . . . ), measuring the pressure
of said gas in said casing at the earth surface to produce a series
of gas pressure measurements (P1, P2, P3 . . . ) that correspond in
time with said gas volume measurements, producing a series of gas
pressure rate of change values (.DELTA.P1, .DELTA.P2, . . . ) based
on said gas pressure measurements and said gas volume measurements
(.DELTA.P1=[P2-P1]/[V2-V1], .DELTA.P2=[P3-P2]/[V3-V2] . . . ), and
comparing each of said gas pressure rate of change values
(.DELTA.P1, .DELTA.P2, . . . ) to a running average value of a
plurality of preceding ones of said gas pressure rate of change
values to detect when a gas pressure rate of change value is
initially less than a predetermined percentage of the running
average value, thereby indicating that said interface is located
within the top region of said chimney below the lower end of said
casing when said gas pressure measurements were made for the less
than a predetermined percentage gas pressure rate of change
value.
14. The method recited in claim 13 wherein said gas volume
measurements are based on measuring the mass of said gas injected
into said casing.
15. The method recited in claim 13 including the following steps
for producing a profile of said chimney: after said interface has
been located at the top region of said chimney below the lower end
of said casing, further injecting said gas into said casing at said
earth surface and measuring said gas pressure at the earth surface
to produce a series of depth gas pressure measurements (Pd1, Pd2,
Pd3, . . . ), measuring the mass of said gas injected into said
casing between each pair of depth gas pressure measurements,
determining a series of change in depth values (.DELTA.d1,
.DELTA.d2, .DELTA.d3 . . . ), each depth value based on a gas
pressure change value (.DELTA.Pd1, .DELTA.Pd2, . . . ) between two
adjacent depth gas pressure measurements (.DELTA.Pd1=Pd2-Pd1,
.DELTA.Pd2=Pd3-Pd2, . . . ) and a gradient (G pressure/distance)
value of said hydrocarbon liquid, wherein the change in depth
values are (.DELTA.d1=.DELTA.Pd1/G, .DELTA.d2=.DELTA.Pd2/G, . . .
), and wherein a series of profile measurements of said chimney are
produced, each said profile measurement defined by (1) a change in
depth value and (2) a volume of gas caused by said mass of said gas
injected into said casing between each pair of corresponding depth
gas pressure measurements which define the change in depth value
(1).
16. The method recited in claim 13 wherein said predetermined
percentage is 50%.
17. The method recited in claim 13 wherein the plurality of
preceding ones of said gas pressure rate of change values has seven
values.
Description
CROSS REFERENCE TO RELATED APPLICATION(S)
[0001] Applicant has filed copending applications entitled "Method
for Detecting Leakage in an Underground Hydrocarbon Storage
Cavern", filed Apr. 25, 2015 and having Ser. No. 14/696,387, Method
for Determining the profile of an Underground Hydrocarbon Storage
Cavern, filed Apr. 25, 2015 and having Ser. No. 14/696,389 (now
U.S. Pat. No. 9,669,997) and Method for Determining the profile of
an Underground Hydrocarbon Storage Cavern, filed May 2, 2017 and
having Ser. No. 15/584,962.
BACKGROUND
1. Field of the Invention
[0002] The field of the present invention is that of test and
measurement equipment used in the oil and gas industry, which
includes the use of large volume underground storage caverns for
storing substantial quantities of petroleum products, such as crude
oil, propane and refined petroleum products, and in particular to
the determination of the configuration of such caverns.
2. Description of the Related Art
[0003] In the use of underground storage caverns, it is important
to determine the approximate shape and volume of the cavern or
sections of the cavern. This has heretofore been done by lowering a
wireline device into the cavern and using sonic devices to measure
distances from the device to the cavern wall. Another technique has
been to pump a liquid into the annulus and determine cavern volume
by measuring the liquid pressure and volume at the annulus and
central tubing at the well surface. Wireline operations are
complex, expensive and subject to leakage of gas or liquid from the
wellhead or wireline connectors. Prior cavern survey techniques are
shown in U.S. Pat. No. 2,792,708, issued May 21, 1957 entitled
"Testing Underground Storage Cavities" and U.S. Pat. No. 3,049,920,
issued Aug. 21, 1962 entitled "Method of Determining Amount of
Fluid in Underground Storage".
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] For a more complete understanding of the present invention
and the advantages thereof, reference is now made to the following
description taken in conjunction with the accompanying original
drawings in which:
[0005] FIG. 1 is an elevation profile view of an underground
storage cavern with an upper chimney section and installed casing
and tubing for filling and removing liquids that are stored in the
cavern, along with equipment for injecting a gas, such as nitrogen,
into the casing with surface equipment for measuring the pressure
and volume (mass) of injected gas,
[0006] FIG. 2 is a chart illustrating measurements of surface gas
pressure as a function of time,
[0007] FIG. 3 is a chart derived from the data in the chart shown
in FIG. 2 showing the rate of change in gas pressure as a function
of time,
[0008] FIG. 4 is a chart illustrating measurements of casing gas
pressure at the earth surface as a function of the volume of
injected gas, together with two calculated rate of change
(pressure/volume) measurements, Rate 1 and Rate 2,
[0009] FIG. 5 is a chart derived from the chart in FIG. 4
illustrating the rates of change of gas pressure as a function of
volume of injected gas, and
[0010] FIG. 6 is a bar graph chart illustrating the calculated
radius of the casing and the upper chimney region of the cavern as
a function of depth below the surface, which is an illustration of
a chimney profile.
DETAILED DESCRIPTION OF THE INVENTION
[0011] Multiple embodiments of the present invention are now
described in reference to the FIGS. 1-6. This invention is for use
with an underground storage cavern, which is also referred to as a
storage well.
[0012] An important objective of the present invention is to
determine when a gas/liquid interface, which is driven downward by
injection of gas into the casing, is located at a position in a
region immediately below the casing shoe. The casing shoe is
positioned at the bottom of the string of casing in the storage
well. The interface level is termed a reference level. This
operation is a part of a process for measuring the profile of a
chimney of an underground storage cavern.
[0013] Measuring the profile of a chimney of a storage cavern is
important because it can indicate the mechanical integrity of the
chimney portion of the storage cavern. If the profile is measured
periodically, for example, every five years, each measurement can
be compared to the last measurement. If the present measurement is
substantially the same, the chimney is likely to be maintaining
structural integrity. But if there is a substantial change, it is
likely that the chimney has been damaged by a wall collapse,
erosion, leakage or possibly blockage. The walls of the chimney are
salt, which can dissolve, erode or break. A change in the chimney
can damage the casing, the casing shoe or weaken the formation
above the chimney and lead to leakage of liquid or gas out of the
cavern into the underground formation regions near the well. This
in turn could lead to gas or liquid leakage at the earth surface,
which could result in a fire or release of toxic gas into the
atmosphere, or lead to ground water contamination.
[0014] Referring to FIG. 1, there is shown an underground storage
cavern 10 which has a section termed a chimney 12 at the upper end
thereof and has a cavern body 14 that is below the chimney and
serves as the primary storage region for the stored liquid. The
chimney can be several hundred feet high and the cavern can be over
a thousand feet in depth and hundreds of feet wide. Such a cavern
can have a capacity to hold several million barrels of hydrocarbon
liquid, for example, crude oil.
[0015] A casing 16 is installed to extend from a wellhead tree 15
at the earth surface 18 down to the top of the chimney 12. A layer
of caprock 19 lies below the earth surface 18. Below the caprock 19
and surrounding the cavern 10 is a salt formation 23. The cavern 10
is formed within the salt formation 23.
[0016] The wellhead tree 15 of the well is located at the earth
surface 18. A structure termed a casing shoe 20 is positioned at
the bottom of the casing 16. The casing shoe 20 provides a
transition from the lower end of the casing 16 into the chimney 12.
A casing liner 21, made of cement, is formed on the outside of the
casing 16 and the interior of the well borehole. The depth of the
casing shoe 20 in a particular well can be found in a log for that
particular well and/or in a completion report for the well that is
filed with the relevant authority. The cement casing liner 21
serves as a barrier to the leakage of fluids (liquid or gas) from
the interior of the chimney 12 into the earth formation surrounding
the casing 16. A string of tubing 22 is optionally positioned
inside the casing 16. The present invention is applicable to a
storage well that includes the tubing 22 and a storage well that
does not have a string of tubing installed inside the casing. The
tubing extends from the wellhead tree 15 down to near the bottom of
the cavern body 14. The casing 16, tubing 22 and liner 21 extend
through the layer of caprock 19. A liquid such as brine 24 is
pumped into the cavern 10 and settles below a liquid 26 because the
brine 24 is more dense than the liquid 26. The liquid 26 can be a
hydrocarbon liquid such as crude oil. When brine is pumped down the
tubing 22 from the surface, it serves to lift the liquid 26 upward
through an annulus 28, which is a region between the casing 16 and
tubing 22, and ultimately to exit the well at the surface through a
flow line 32. There may be a gas/liquid interface 30 between the
liquid 26 and a gas 52 in the annulus 28 and this interface can
extend down into the chimney 12 and cavern body 14. A liquid/liquid
interface 31 is located between the liquid 26 and the more dense
brine 24.
[0017] The storage cavern 10 may have multiple casings positioned
concentric about the tubing 22. Typically, the outer casings extend
less deep into the earth formation than the innermost casing, such
as casing 16.
[0018] Further referring to FIG. 1, a gas tank 34, preferably
containing compressed or liquified nitrogen, is coupled through a
valve 36 to a mass flow meter 38. An example of a mass meter 38 is
a Micro Motion ELITE Coriolis Flow Meter. The valve 36 can be set
to have a constant flow rate of nitrogen gas from the tank 34 to
the mass meter 38 and into the casing 16. Another method for
determining the mass of gas injected into the well is to weigh the
gas tank 34 continuously or periodically. A weight measurement as a
function of time indicates the flow rate of gas into the well. A
still further technique is to measure the pressure of the gas in
tank 34 and calculate the volume of gas in the tank from this
pressure measurement.
[0019] A pressure meter 40 is mounted to the casing 16 for
measuring the pressure of the gas in the casing at the earth
surface. The mass meter 38 is connected through a data line 42 to a
multichannel data acquisition recorder 44 so that the mass readings
can be recorded as a function of time. Likewise, the pressure meter
40 is connected through a data line 46 to the recorder 44 for
recording pressure measurements. Wireless links can be used in
place of the data lines if desired. The surface gas pressure and
gas mass readings are correlated with each other as shown in FIG.
2.
[0020] The meter 38 directly measures the mass of gas that passes
through the meter. The mass reading can be converted to volume by
using the well-known gas law equations. The gas volume (mass)
measurement is expressed in SCF (Standard Cubic Foot).
[0021] The temperature of the gas in the casing 16 at the earth
surface is measured by a thermometer 48 and the measured
temperature readings are sent through a data line 50 to the
recorder 44.
[0022] The recorder 44 is coupled to a computer 49 through a data
line 51 to provide the data collected from the meter 38, meter 40
and thermometer 48 to the computer 49 for processing and display,
as further described below.
[0023] Further referring to FIG. 1, the gas injected into the
casing-tubing annulus 28 is indicated by the reference numeral 52.
The interface 30 is shown in the annulus 28 and can be located at
any depth in the casing 16. The interface 30 can initially be at
the top of the casing 16 at the earth surface 18 and then driven
downward into the well as gas 52 is injected into the casing 16
from the tank 34. Representative depth locations of the interface
30 are shown by the reference numerals 62, 64, 66, and 68. The
interface 30 can be driven down into the chimney 12 and the cavern
body 14.
[0024] A first embodiment of the invention is now described in
reference to FIGS. 1, 2 and 3. In this embodiment the valve 36 is
set to inject a constant rate of flow of nitrogen gas from tank 34
into the casing 16. For the illustrated example, this rate is 1,000
SCF/min. The flow of gas 52 causes the gas pressure in the casing
16 at the earth surface to increase. This is shown in FIG. 2 which
is a chart illustrating the increase in casing gas pressure, the
vertical scale, as a function of time, the horizontal scale. A data
line 70 illustrates the measured values of gas pressure as a
function of time. A casing pressure rate of change is calculated by
subtracting a gas pressure at a first time from a gas pressure at a
second time and dividing this pressure difference by the interval
of time between the first time and the second time. This chart
shows that starting at time minute 51, the casing pressure
increases at a constant rate until it reaches time 53:04. This rate
is approximately 11 psi/min. After time 53:04 the rate of change is
at a lesser rate which decreases with time. This is shown by line
72.
[0025] The values for the data shown in FIG. 2, together with the
rate of change of pressure is shown in Table 1 below. The rate of
change is calculated for each 12 second interval, and is expressed
in psi/min. The pressure values (P1, P2, P3, . . . ) are taken at
respective times (T1, T2, T3, . . . ). The calculation for pressure
rate of change per unit of time (.DELTA.P1, .DELTA.P2, .DELTA.P3 .
. . ) is (.DELTA.P1=[P2-P1]/[T2-T1], .DELTA.P2=[P3-P2]/[T3-T2], . .
. ), as shown in the following Table 1.
TABLE-US-00001 TABLE 1 Rate of Time T Pressure P Pressure Change
(min:sec) (psi) (.DELTA.P psi/min) 51:00 1364.5 -- :12 1366.7 11
:24 1368.9 11 :36 1371.1 11 :48 1373.3 11 52:00 1375.5 11 :12
1377.7 11 :24 1379.9 11 :36 1382.1 11 :48 1384.3 11 53:00 1386.5 11
:12 1387.3 4 :24 1387.8 2.5 :36 1388.0 1.0
[0026] The rate of change values for the data shown in FIG. 2 are
illustrated in the chart shown in FIG. 3. The calculated rate of
change values are plotted as a function of time. The rate of change
value is essentially constant from time 51 to time 53 at a value of
11 psi/min and then it rapidly drops to 4 psi/min at 53:12, then
2.5 psi/min at 53:24 then down to 1.0 psi/min at 53:36.
[0027] Referring back to FIG. 1 illustrates the cause for the
change in the gas pressure rate of change while a constant flow
rate of gas 52 is injected into the casing 16 at the surface from
time 51 minutes until time 54 minutes. It has been found that in
caverns such as 10, that a change in pressure of the gas in a well
at a given depth causes a change in the depth of the interface that
is a function of the pressure change and the gradient of the liquid
at that depth. At time 51 the interface 30 is located at, or near,
the earth surface 18. As the gas 52 is initially injected into the
casing 16, the interface 30 is located in the annulus 28. This
annulus, as shown in FIG. 1, has a constant cross section size from
the earth surface 18 down to the casing shoe 20 at the bottom end
of the casing 16. However, if the casing 16 has been damaged, a
casing liner may be installed and this liner will have a lesser
diameter. Within the reduced diameter section the rate of change of
gas pressure will be constant, but the value will be different.
Within any section of casing with a constant diameter, the rate of
change of gas pressure will be constant. A given volume of gas
injected into the casing repeatedly causes the same change in
pressure because the geometry within the annulus 28 is constant. A
given volume of injected gas depresses the interface 30 the same
distance each time that the given volume of gas is injected. The
rate of change of pressure is constant as long as the interface 30
is in the annulus 28. In FIG. 2, the interface 30 reaches the
bottom of the casing 16 at the 53:04 time mark (indicated by arrow
88) and then enters into the top of the chimney 12. The top of the
chimney 12 has a significantly larger cross section area in
comparison to that of the annulus 28 and therefore a larger volume
per unit of depth. Due to the larger volume of the chimney 12 the
given volume of injected gas depresses the interface 30 a shorter
distance as shown and therefore there is a smaller change in
pressure. As shown in FIG. 3, the rate of pressure change from 51
min. to 53 min is 11 psi/min, but after the 53:04 time mark, the
rate of pressure change per unit of time drops to 4 psi/min, then
2.5 psi/min and then to 1.0 psi/min. This corresponds to the
interface 30 leaving the constant cross section annulus 28 and
entering into the top region of the chimney 12 that exhibits a
larger cross-sectional area.
[0028] A first technique for determining when the interface 30
leaves the bottom of the casing 16 and enters into the top of the
chimney 12 is to compare each calculated pressure rate of change
value to the immediately preceding pressure rate of change value
and determine when a pressure rate of change value is initially
less than a predetermined percentage of the value of the preceding
rate of change value. If the predetermine percentage change is
selected to be 50%, each pressure rate of change value is compared
to the preceding rate of change value. For each of the values shown
in Table 1 from time 51 to time 53, the percentage change for each
value from the previous value is 0%. But from time 53:00 min to
time 53:12 min, the pressure rate of change goes from 11 to 4. This
is a reduction of 64%. With a threshold set at 50%, this indicates
that the interface 30 entered into the top region of the chimney 12
during the time from 53:00 min to 53:12 min.
[0029] This example uses 12 seconds as the interval for calculating
pressure rate of change, however, other intervals, longer or
shorter, can also be used.
[0030] Another technique for determining when the interface 30
leaves the casing 16 and enters into the top region of chimney 12
is to compare each pressure rate of change value to an earlier
pressure rate of change value that is not the immediately preceding
value. For example, each value could be compared to the second
preceding value. In the above example, there would be the same
result because the second preceding value is 11 for comparison to
the present value of 4. This technique could be preferred if the
change in area from the annulus 28 at the end of the casing 16 into
the top region of the chimney 12 is more gradual and therefore the
amount of the rate of pressure change is less from sample to
sample. See Table 2 below.
TABLE-US-00002 TABLE 2 Rate of Pressure Change Time (.DELTA.P
psi/min) 51:00 -- :12 11 :36 11 :48 11 52:00 11 :12 10 :24 9 :36 6
:48 6 53:00 4 :12 3 :24 3
[0031] Referring to the data in Table 2, for a rule that sets the
comparison of each rate of pressure change value to the third
preceding value with at least a 50% reduction, the value "4" is the
value in the time sequence that meets this rule. This rule
indicates that the interface 30 entered into the upper region of
the chimney 12 during the time interval from 52:24 to 53:00.
[0032] A still further technique is to compare the present value to
a running average of prior values. For example, the present value
could be compared to the average of the preceding four rate of
change values. See Table 2 above. With a 30% threshold, the first
value that is less than 30% of the running average of the four
preceding four values is "6". The average of the four preceding
values is 10 and 6 is 40% less than 10. Using this rule, the
interface 30 is indicated to have entered into the upper region of
the chimney 12 during the time interval between 52:24 and
52:36.
[0033] The rule to use, and the percentage change to use, in a
particular application can depend on the known or anticipated
geometry of the well or the nature of the data that has been
collected.
[0034] One rule is to use the average of multiple values and
compare to a present measurement of rate of gas pressure change. A
change from the average of 30% or 50% can indicate the inflection
point. This detected change will be close to the actual point where
the interface enters into the chimney. A running average of seven
preceding values in Table 2 with at least a 40% difference less
than the average selects the value "6" at 52:48.
[0035] A further embodiment of the present invention is now
described in reference to FIGS. 4 and 5. For detecting the
interface 30 position at the reference level, which is in the top
region of the chimney 12, this embodiment utilizes the rate of
change in gas pressure as a function of the cumulative volume of
gas pumped into the casing 16, in contrast to the embodiment
described in reference to FIGS. 2 and 3 which is based on a rate of
change of gas pressure as a function of time. Referring to FIG. 4,
a data line 80 is a plot of the standard volume (mass) of injected
gas along the horizontal axis and the gas pressure in the casing 16
at the earth surface 18 along the vertical axis. For this set of
data, the line 80 has essentially a constant average rate of change
(Rate 1) of 10.8 psi/100 SCF from volume 0 to volume 210 SCF at
line 82. After volume 210 SCF, the average rate of change goes down
to approximately 1.25 psi/100 SCF (Rate 2).
[0036] For this embodiment, the rate of flow of gas 52 injected
into the casing 16 need not be a constant rate, it can vary with
time. Data points together with calculated gas pressure rates of
change as a function of cumulative gas volume are shown in Table 3
below. The gas pressure rate of change (.DELTA.P1, .DELTA.P2, . . .
) is determined by measuring a series of gas volume measurements
(V1, V2, V3 . . . ) and simultaneous time corresponding gas
pressure measurements (P1, P2, P3 . . . ). The rate of gas pressure
change is calculated as (.DELTA.P1=[P2-P1]/[V2-V1],
.DELTA.P2=[P3-P2]/[V3-V2] . . . ).
TABLE-US-00003 TABLE 3 Volume Gas Pressure Rate of Gas Pressure
Injected V P Change .DELTA.P (SCF) (Psig) (psi/100 SCF) 0 1364.0 --
25 1366.7 10.8 50 1369.4 10.8 75 1372.1 10.8 100 1374.8 10.8 125
1377.5 10.8 150 13180.2 10.8 175 1382.9 10.8 200 1385.6 10.8 225
1387.4 1.8 250 1389.0 1.6 275 1390.25 1.25 300 1391.5 1.25
[0037] For this embodiment, the methods for detecting when the
interface 30 has entered into the top region of the chimney 12 are
the same as described above. First technique is when a gas pressure
rate of change value is less than a predetermined percentage of an
immediately preceding value. If the predetermined percentage is
50%, the identified rate of change value in Table 3 is 1.8 which
corresponds to the injected gas volume of 225 SCF. If the value is
compared to a third preceding value, the result is also the 1.8
value. The comparison of a running average of the preceding four
rate of change of gas pressure values with a predetermined
percentage of 30% also selects the 1.8 psi/100 SCF value. This
selection indicates that the interface 30 enters into the topmost
region of the chimney 12 between the measurements of 200 SCF and
225 SCF. A running average of seven prior values with at least a
40% change deems the 1.8 value as the transition reading.
[0038] FIG. 5 is a chart with data curve 86 showing the relation of
the cumulative volume of injected gas 52 with the rate of change of
gas pressure in the casing 16 at the earth surface 18. The gas
injection is started when the interface 30 is located at or near
the earth surface. As the interface 30 is pushed downward in the
casing annulus 28, the rate of increase in surface pressure is
uniform because the geometry of the annulus cross section is
constant, if the internal diameter of the casing remains constant.
When approximately 200 SCF of gas has been injected, the pressure
rate of change begins to drop substantially as a function of the
volume of injected gas. Note that the gas pressure does not drop,
it is the rate of change in the gas pressure that drops. This is
due to the interface 30 entering into the top region of the chimney
12 which has a much larger volume per unit of depth than that of
the casing annulus 28. Much more gas is required to lower the
interface a given distance than was needed to lower the interface
such a given distance in the casing annulus 28.
[0039] Multiple embodiments of the invention are described above to
detect when the interface 30, which is driven downward into the
well by the injection of gas, passes through the bottom end of the
casing 16 into the top region of the chimney 12, by identifying
when a sudden change occurs in the gas pressure rate of change, in
comparison to either time or volume of injected gas. When the
interface 30 is located immediately below the casing shoe 20,
typically within two to five feet, this is termed the reference
level of the interface 30. After the interface 30 has been
determined to be at this reference level, further steps in
accordance with the invention are to measure the volumes of
sections of the chimney 12 located below the reference level. This
constitutes establishing a profile of the chimney 12.
[0040] Referring to FIG. 1, the interface 30 can be driven downward
to the depth 62, which is the reference level detected as described
above. The next measurements and calculations are directed to
determining the volume of the chimney 12 at measured depths. In
particular, the measurements are directed to determining change in
depth values (.DELTA.d1, .DELTA.d2, .DELTA.d3 . . . ) based on
changes in gas pressure measurements at these depths in the cavern
storage well. The pressure measurements at these depths are termed
Pd1, Pd2, Pd3, . . . The change in gas pressure measurements at
these depths are termed .DELTA.Pd1, .DELTA.Pd2, .DELTA.Pd3 . . .
The changes in depths are calculated by the formula
.DELTA.d1=.DELTA.Pd1/G, .DELTA.d2=.DELTA.Pd2/G, G is the gradient
(psi/foot) of the hydrocarbon liquid. The gradient G can vary with
depth. The gradient (psi/foot) of the liquid 26 is either measured
for the well under test or determined by reference to standard
values for the type of liquid 26 in the well.
[0041] The pressure at a particular depth is based on the surface
pressure measurement of the gas pressure in the casing 16 at the
earth surface. The pressure at a depth, such as depth 62, shown in
FIG. 1. is the surface measured pressure plus the pressure due to
the weight of the gas column from the surface down to the depth 62.
The weight of this column is determined by the length of the
column, the chemical composition of the gas, the pressure of the
gas and the temperature of the gas. These calculations for
down-hole pressure are well known in the art and widely used in the
oil and gas industry. Table 4 below illustrates downhole pressure
calculated from surface pressure for a particular well. Similar
calculations can be made for any storage cavern well.
TABLE-US-00004 TABLE 4 Interface Pressure Surface Depth at Depth Pd
Pressure P (feet) (Psig) (Psig) 0 773.7 773.7 100 809.8 807.2 197
844.8 839.6 300 881.9 873.8 400 918.0 907.0 500 930.1 940.0 600
990.1 972.8 748 1043.5 1020.9 800 1062.3 1037.7 900 1098.3 1069.3
1000 1134.4 1100.7 1100 1170.5 1131.7 1200 1206.5 1162.3 1300
1242.6 1192.6 1400 1278.7 1223.2 1450 1296.7 1238.4 1500 1314.8
1253.6 1600 1350.8 1283.7 1700 1386.7 1313.6 1800 1423.0 1343.3
1900 1459.0 1372.7 1970 1484.3 1393.1 1985 1489.7 1397.5 2000
1495.1 1401.8
[0042] The actual volume of gas at a depth in the well due to the
injection of gas at the surface is less than the measured standard
volume of gas injected at the surface due to the greater gas
pressure and temperature at the depth. The calculation of the
volume of gas at depths in the well is well known in the art and
widely used in the oil and gas industry. The standard volume (mass)
of injected gas injected at the surface between two points in time
is known together with the surface pressure and temperature. The
pressure and temperature at depth are known. The temperature at
each depth is available from a temperature survey previously taken
for the well, or known for a geographic region. The actual volume
at depth is calculated by use of the gas law equations using all of
these parameters, which are the standard volume, at the surface
pressure and temperature, and the at depth pressure and
temperature. See Table 5 below showing the standard volume of gas
injected at the surface and the corresponding actual volume at
given depths. For example, for 49.8 SCF of N2 injected at the
surface, there is a one cubic foot displacement at 0 depth (the
earth surface). But when the interface is at, for example 1400
feet, there must be an injection at the surface of 74.0 SCF of N2
for a of one cubic foot volume of gas at 1400 feet. The at-depth
volume of gas is based on the standard volume (mass) of gas
injected at the surface.
TABLE-US-00005 TABLE 5 SCF of N2 Depth Gas/Cu. Ft (feet) (Avg. P
& T) ) 0 49.8 100 51.4 197 52.9 300 30.5 400 56.0 500 57.4 600
58.9 748 61.5 800 62.2 900 64.0 1000 65.8 1100 67.8 1200 69.8 1300
71.9 1400 74.0 1450 75.1 1500 76.1 1600 78.2 1700 80.2 1800 82.3
1900 84.3 1970 85.6 1985 86.1 2000 86.5
[0043] Referring to FIG. 1, when the interface 30 has been
depressed to depth 62, the reference level, the surface gas
pressure is measured and additional gas is injected. A second gas
pressure measurement is made and the standard volume of gas
injected between the gas pressure measurements is determined. The
two surface pressure measurements are used to determine the
at-depth pressure values, as discussed above. The difference in
these two pressure values (Pd2-Pd1) is multiplied by the gradient G
of the hydrocarbon liquid and the product is the distance
(.DELTA.d1) that the interface moved between the two pressure
measurements. .DELTA.d1 is the distance that the interface 30 moved
downward from the reference level. If the .DELTA.d1 value is 10
feet, the resulting depth of the interface is depth 64 as shown in
FIG. 1. The incremental standard volume of gas injected at the
surface is used to determine the actual volume of liquid displaced
by the additional gas .DELTA.V1 between the depths 62 and 64. The
measured profile volume of the chimney 12 between depths 62 and 64
is a height of M1 and a volume of .DELTA.V1. Assuming that the
chimney 12 has a cylindrical geometry and there is no tubing string
in the cavern, the cavern radius (rc) is determined by the formula
(rc= (V/(.DELTA.d.pi.)) This radius is illustrated in FIG. 6 for
each depth interval. If there is a tubing string present in the
cavern, and the tubing string has a radius of rt, the cavern radius
rc is (rc= (V/(.DELTA.d.pi.)+rt.sup.2)
[0044] When the interface 30 has been driven down to the depth 64
and the pressures and gas volume has been recorded, more gas is
injected to drive the interface 30 further downward. A new at-depth
pressure is determined from a surface measurement and the volume of
gas injected at the surface is measured and used to determine the
volume of gas at the depth between the last two pressure
measurements. The depth of movement .DELTA.d2 is determined as
described above using the pressure differential at the depths and
the gradient of the liquid 26. This determines the height and
volume for another profile section of the chimney 12. The radius
for this profile section of chimney 12 is then calculated.
[0045] FIG. 6 is a bar graph that shows the radius of the chimney
12 (horizontal axis) as a function of the depth (vertical axis) in
the cavern storage well. Each of the bars 92, 94, 96, 98 and 100
represent a radius in the casing 16 or the chimney 12 at the
indicated depths. For example, bars 92 and 94 represent the radius
of the casing 16. This calculation takes into consideration the
cross-section area of the tubing 22 and therefore the volume of the
tubing 22. Bars 98 and 100 indicate an average radius in the
chimney 12 of approximately 50 inches at depth range 1985-1995 for
bar 98 and depth range 1995-2005 for bar 100. The radius values are
produced as described above. The bar graph in FIG. 6 can be used as
a reference to compare to future profile measurements for the
chimney 12 to evaluate the mechanical integrity of the chimney 12
over time.
[0046] Although several embodiments of the invention have been
illustrated in the accompanying drawings and described in the
foregoing Detailed Description, it will be understood that the
invention is not limited to the embodiments disclosed, but is
capable of numerous rearrangements, modifications and substitutions
without departing from the scope of the invention.
* * * * *